1. Field of the Invention
This invention relates generally to turbine and burner control, and more particularly to characterizing a combustion flame within a turbine or burner to facilitate control of the turbine or burner, and to detecting contaminants in fuel used in the turbine or burner.
2. Discussion of the Related Art
Turbines and burners are used to produce power from gas fuel and liquid fuel. generally, turbines are characterized as power-producing devices that operate at a high internal pressure, while burners operate at atmospheric pressure.
FIG. 1 depicts a turbine system for producing power. Although a turbine system is described below, the concepts are equally applicable to burner systems, and therefore it should be understood that the term "turbine" as used in this disclosure also refers to burners.
FIG. 1 shows a turbine 10 coupled to a turbine controller 11. The turbine 10 receives air 22 via air inlet 12, receives fuel 23 via fuel inlet 13, generates power 24 at power output 14, and emits exhaust 25 at exhaust outlet 15. Typically, the exhaust outlet 15 is coupled to an input 26 of an exhaust stack 27. The exhaust stack 27 may include additional inputs 28 that receive exhaust 29 from other turbines. An air flow probe 16 is coupled to the air inlet 12 and also coupled to the turbine controller 11. Additionally, a fuel flow probe 17 is coupled to the fuel inlet 13 and also coupled to the turbine controller 11. Although the air flow probe 16 and fuel flow probe 17 are each depicted in FIG. 1 as being external to the turbine 10, either or both may instead be disposed internal to the turbine 10 or anywhere along the respective path of air flow or fuel flow. The turbine system may further include a pressure probe 18 and a number of external thermocouples 19, each of which is coupled to both the turbine 10 and turbine controller 11. External thermocouples 19 typically provide temperature measurements of the fuel 23, exhaust 25, turbine surface, and the like.
In operation, the turbine controller 11 receives measurements from the turbine sensors (e.g., air flow probe 16, fuel flow probe 17, pressure probe 18, and external thermocouples 19), and provides control signals 42 to control the operation of the turbine 10 according to a desired operating mode. Examples of control signals 42 include signals that control injectors within the turbine, signals that control the amount of fuel input to the turbine 11, signals that control an air/fuel ratio within the turbine, and other control signals as known in the art.
On Nov. 15, 1990, the Clean Air Act Amendments of 1990 (CAA) were enacted (Public Law 101-549, 104 Stat. 2399, codified at 42 U.S.C. 7401-7671q.) The second phase of the Clean Air Act requires that every industrial facility be controlled to emanate less than a predetermined amount of Nitrogen Oxide Compounds (NOx). The air quality planning requirements for the reduction of NOx emissions through reasonably available control technology (RACT) are set out in .sctn. 182(f) of the CAA, which is incorporated by reference in its entirety.
On Nov. 25, 1992, the EPA published "State Implementation Plans; Nitrogen Oxides Supplement to the General Preamble; Clean Air Act Amendments of 1990 Implementation of Title I; Proposed Rule," (The NOx Supplement) which describes and provides preliminary guidance on the requirements of .sctn. 182(f), and is also incorporated by reference in its entirety. Such requirements present a particular challenge to owners and operators of combustion turbines and burners. To meet the requirements of the Clean Air Act, it is necessary to determine the NOx content of the exhaust. Typically, compliance with the Clean Air Act is determined by measuring the content of exhaust that passes through an industrial plant's exhaust stack. If the measurement indicates too much of any chemical, it is generally necessary to take additional steps to achieve compliance with the Clean Air Act. For example, the exhaust stack may be modified to increase the height at which it emanates. Alternatively, or in combination, post-exhaust devices may be added to reduce the pollution content of the exhaust. These devices typically add to the operating and maintenance cost of the industrial plant. If the requirements of the Clean Air Act cannot be met by any of these approaches, the Clean Air Act includes a provision by which an industrial plant may purchase or otherwise obtain the right to emanate at a higher rate than other organizations.
Generally, however, it is desirable to control the contributing turbines or burners to operate more efficiently. One manner in which to improve the operating efficiency is to operate the turbine or burner at an optimized combustion flame temperature. In such a manner, an industrial plant may meet the requirements of the Clean Air Act, reduce pollution, and increase the overall efficiency of the turbine or burner, by, for example, reducing operating costs by reducing the amount of fuel utilized.
Many industrial facilities include an exhaust stack that passes the combined exhaust from several turbines and burners. In such cases it is difficult to determine the flame quality of any one of the contributing turbines or burners because the several exhausts have been combined and passed through the exhaust stack. Thus, the characteristics of the combined exhaust cannot be easily attributed to any particular contributing turbine or burner.
Additionally, even in an arrangement in which a single exhaust stack is used for a single turbine or burner, measurements made at the exhaust stack are generally unsuitable for feedback control of the turbine or burner because of the delay in feedback and the poor accuracy of such measurements.
A temperature probe may be positioned close to the exhaust of each turbine in order to provide an approximate indication of the combustion flame temperature. Such an arrangement, however, is quite susceptible to leakage into or out of the exhaust path that will, in turn, affect the quality of any measurements made by such a probe. Furthermore, the combustion flame temperature must be back calculated in such an arrangement, which often yields a temperature characterization of questionable accuracy.
Moreover, some turbine systems include a plurality of burners that share a single exhaust. For example, the GTX100 gas turbine, available from ABB STAL AB of Finspong Sweden, includes a plurality of individual combustion burners, each of which contributes to a single exhaust diffuser. The exhaust diffuser is connectable to an exhaust stack or a waste heat recovery unit that may be controlled to further reduce emissions. Any single measurement, however, made at the exhaust diffuser represents only the aggregate performance of all of the plurality of individual combustion burners. In such an arrangement, it is difficult to determine individual burner flame quality based upon the single shared exhaust. This arrangement provides a particular challenge for individually tuning the performance of an individual combustion burner, or performing fault isolation on an individual combustion burner if it is suspected that one may have failed.
Direct measurement of combustion flame temperature is generally not implemented because most known thermocouples cannot survive the high temperature environment within the combustion chamber of a turbine. Moreover, the response time of known thermocouples is in the region of two seconds, which is usually longer than desirable for the purpose of the turbine controller providing control signals in a timely manner to efficiently control the turbine.
In addition to controlling the operation of a turbine or burner to control noxious emissions, it is also important to control the amounts of contaminants within the turbine. Excessive amounts of contaminants can seriously damage components of the turbine. Some contaminants, in combination with the high operating temperature environment, can corrode and erode components, such as turbine blades, or anything located in the hot section, leading to improper operation. As these components are very expensive, anything that can be done to detect excessive contaminant levels will directly result in cost savings.
Most contaminants in a turbine or burner come from the contaminants introduced by the fuel that is being burned. Many substances are allowed in fuel in specified low levels but not at high levels that could lead to corrosion or scaling. Thus, it is known to measure the contaminant levels in the fuel being used. One method of measurement is the detection of discrete frequency bands associated with the specified emission lines for known elements. One such method is taught by Goff et. al. in U.S. Pat. No. 4,896,965 entitled "Real-Time Alkali Monitoring System" issued Jan. 30, 1990. Goff teaches a fiber optics based optical emission line monitoring system used to detect spectral emission lines for particular contaminants, for example, sodium.
A sample of the process stream is diverted to a combustion burner where it is combusted to produce flame emissions. The flame emissions are then analyzed at the wavelength of the contaminant of interest. As Goff has calibrated the operation of this sample combustion chamber, the intensity at a particular wavelength is indicative of a contamination level.
Goff has calibrated the sample combustion chamber so that the only unknown variables in its operation are the contaminant levels in the fuel that is being burned. This sample combustion chamber is not operating under varying load conditions or with changing fuel rates. Thus the teachings of Goff are not applicable to monitoring the combustion flame in a combustor operating under varying real-world operating conditions. The changes in load and fuel would render the calibrated measurements of Goff meaningless when monitoring an actual load-bearing combustion flame. Additionally, as Goff is only measuring the contaminants in the fuel, it is not measuring a contamination level in the combustor that was the result of continuous use of fuel.
Accordingly, an apparatus and method are needed to monitor the contaminant levels in a load-bearing combustor (turbine or burner) in real-time.